Drilling costs are a critical factor in determining the financial returns from an oil and gas investment. This is particularly so in the offshore environment, where operating costs are high, and in wells in which drilling problems are likely to occur. Severe vibrations in particular have been shown to be harmful to downhole equipment used for drilling oil and gas wells. Among them, lateral vibrations, particularly backward whirl, are commonly associated with drillstring fatique failure (wash-outs, twist-offs) excessive bit wear and measuring-while-drilling (“MWD”) tool failure. Lateral vibrations are caused by one primary reason—mass imbalance through a variety of sources, including bit-formation interaction, mud motor, and drillstring mass imbalance, among others.
A rotating body is unbalanced when its center of gravity does not coincide with its axis of rotation. Due to such a crookedness or mass imbalance, centrifugal forces are generated while the unbalanced drillstring is rotating. The magnitude of the centrifugal force depends, inter alia, upon the mass of the drillstring, the eccentricity, and the rotational speed. In general, the higher the rotational speed, the greater the centrifugal force. Thus, a common practice is to lower the rotary speed when severe lateral vibration occurs. However, those of ordinary skill in the art will appreciate that vibration may not be reduced if the lower rotational speed results in a resonant condition in the assembly. A resonant condition occurs when the rotational frequency of any one of the excitation mechanisms matches the natural or resonant frequencies (bending, axial, or torsional) of the bottom hole assembly (“BHA”), often referred to as critical rotary speeds or CRPMs. Under a resonant condition, the BHA has a tendency to vibrate laterally with continuously increasing amplitudes, resulting in severe vibration and causing drillstring and MWD failures.
Those of ordinary skill in the art will appreciate that it is important to identify and avoid critical rotary speeds during drilling operation. A number of finite element analysis-based computer programs have been developed to predict critical rotary speeds in drillstrings. However, the accuracy of predictions from such programs is often limited due to uncertainties in the input data and specified boundary conditions. Conventional BHA dynamics software is usually run during well planning or sometimes at the rig, when the BHA is made up. A set of predicted critical CRPMs to be avoided is then provided to the driller.
Common operational difficulties with conventional approaches to avoiding CRPMs are (i) complex BHA modeling and results; (ii) inaccurate modeling and results due to incorrect input data; and (iii) modeling results not being used in conjunction with real-time vibration data to optimize the drilling process. That is to say, in the prior art is has not customarily been the case that dynamics analysis is carried out in an integrated, closed-loop manner, but instead occurs primarily or exclusively during the well-planning phase, such that there is limited opportunity for optimization of well operation.